Page 236 - Fundamentals of Gas Shale Reservoirs

216 PASSIVE SEISMIC METHODS FOR UNCONVENTIONAL RESOURCE DEVELOPMENT

mechanism solution. The intermediate stress axis is therefore the methods were developed in the early 2000s and are coming
same as N, the neutral particle‐motion axis. For this reason, into ever‐wider use. This section focuses on microseismic
mixed populations of focal mechanism solutions are sorted downhole monitoring. Surface monitoring is discussed in
most easily by inspecting the N‐axis orientations. Section 10.5. Many of the principles used in downhole
As discussed in Sections 10.2.2.2 and 10.2.2.3, the passive monitoring are borrowed from earthquake seis­
common and useful simplification that MEQs result from slip mology. As such, they have been tested extensively and used
in a uniaxial stress field, that is, this movement occurs in a for several decades.
plane that contains the P and T axes, Smax, Smin, and the slip
line, is not strictly true. Fortunately, the average orientations 10.4.1 Downhole Monitoring Methodology
of orthorhombic sets of newly formed faults approximate
faults formed in a uniaxial stress field. Statistical methods 10.4.1.1 Overview Microseismic downhole monitoring
also can address the problems posed by reactivated fractures. of reservoir stimulation involves one or more monitoring
These issues and procedures using populations of focal wells in which borehole sensors are operated. The moni­
mechanism solutions to estimate the reservoir stress are toring well can be a nearby well drilled specifically for that
discussed in Section 10.6.2. purpose or another production well from which production
is being temporally or permanently halted. Wells being very
expensive to drill, downhole monitoring rarely involves
10.3.3 Other Types of Seismic Activity Produced by more than one monitoring well.
Hydraulic Fracturing
Downhole monitoring of hydraulic stimulation has been
MEQs are not the only type of seismic activity produced by successfully carried out since the early 1980s (e.g., Pearson,
hydraulic fracture treatments. The study of non‐MEQ seismic 1981). Figure 10.7 shows the locations of the treatment and
phenomena is a new and rapidly developing field of study. monitoring wells of a typical downhole microseismic moni­
Das and Zoback (2013a, b) have demonstrated that LPLD toring setup for a hydraulic fracturing project.
activity produced by fracture treatments can represent 40 The use of a single well is a source of uncertainty because
times more energy than the MEQs produced by the hydraulic each earthquake is observed from only one direction. This
fracture treatment. LPLD is a long‐lasting phenomenon problem of aperture is a significant challenge in downhole
without distinct first arrivals that is analogous to tectonic microseismic monitoring. Aperture is defined as a window
tremor. Like tectonic tremor, LPLD is dominated by S‐wave that limits the amount of information recorded; it is the size
energy although P‐wave energy is also present (e.g., La Rocca and positioning of a survey needed to accurately image an
et al., 2009). The Extended Duration Signal (EDS) described area of interest. Common practice uses a limited acquisition
in vertical‐component surface array data by Sicking et al. aperture typically placed in only a single monitor well. This
(2014) is dominated by P‐wave energy. Further study of EDS gives rise to event identification limitations during processing.
using multicomponent data to search for possible weak asso­ Due to the limited aperture, it is difficult to constrain the loca­
ciated shear waves is underway at the time of this writing. tion and horizontal and vertical extent of the microseismic
Such strong, long‐lasting P‐wave emissions may represent event. Multiple monitor arrays reduce the location uncertainty,
fluid resonance comparable to water hammering in household but the array aperture may still not be sufficient to resolve
water pipes. Such fluid resonance is expected to produce pri­ the exact location of the microseismic event temporally and
marily P‐wave energy, and downhole microseismic workers spatially and its size.
have reported this phenomenon (e.g., Tary and van der Baan, Downhole monitoring generally involves three‐component
2012). Undiscovered hydraulic fracture‐related seismic phe­ (one vertical, Z; and two horizontal components, X and Y)
nomena may exist. Regardless, it is rapidly becoming clear receivers that record both P (compressional)‐ and S (shear)‐
that MEQs represent only part of the seismic signal produced waves. The receivers are positioned and clamped to the cas­
by fracture treatments of unconventional reservoirs, and in ing along the wellbore. The length of the receiver array is the
some reservoirs represent only a small part of the signal. total aperture available for event location. Figure 10.8a
shows typical waveforms for a microseismic event recorded
using a 16‐level downhole array of geophones. Consistent
10.4 MICROSEISMIC DOWNHOLE MONITORING with the notion that the event represents predominantly a
shear slip, the shear waves have much larger amplitudes
Other than well production, the monitoring of microseis­ than the compressional waves shown in Figure 10.8a. Since
micity induced during reservoir simulation is the best means the receiver orientations are unknown, their orientations are
of assessing the stimulation effectiveness of unconventional determined before the beginning of the actual monitoring.
reservoirs. For many years, downhole monitoring was the This is achieved using data from perforation shots or string
only method to monitor such MEQs and is still the most com­ shots of known locations. Examples of perforation shot
monly used method. Surface and near‐surface monitoring seismograms are displayed in Figure 10.8b. The calculated